Vanoil Wraps Up Seismic Program in Kenya Block

- Vanoil Wraps Up Seismic Program in Kenya Block

Tuesday, September 13, 2011
Vanoil Energy Ltd.

Vanoil has completed its 2011 2D seismic program on Block 3B in Kenya. Vanoil's 100% owned Blocks 3A and 3B in Kenya cover approximately 24,000 square kilometers and are part of the vastly under-explored prolific Cretaceous Central African Rift Basin System in Kenya.

Vanoil's 2011 seismic program in Block 3B covered approximately 398 line-km and was completed on budget and schedule. The program was designed to cover several leads previously identified on the re-processed 1975 Chevron and the 2010 Vanoil seismic data in Block 3B. The 2011 seismic data is high quality with location, time and amplitude content having been jointly assessed and controlled by the contractors; Bureau Geophysical Prospecting (BGP) and RPS. This premium data has been gathered to further image some specific structural leads and as a reconnaissance program to identify more new leads in Block 3B. In addition, the 2011 seismic program was also designed to enable Vanoil to improve on the geologic model in the Lamu Basin, one of the three basins identified on the Vanoil Blocks.

The 2011 2D seismic program in Block 3B consisted of 398 kilometers of additional seismic bringing the cumulative total to 845 kilometers of 2D seismic coverage completed by Vanoil to date on Blocks 3A and 3B in 2010/2011.

The 2011 Vanoil 2D seismic program data will now be sent to Statcom in Calgary Alberta for processing, following which, the data will be interpreted and integrated with the reprocessed and interpreted 1975 Chevron and 2010 Vanoil data. With the newly acquired data, the Company expects to add significantly to the resource assessment incorporated in the previously announced Sproule 51 101 report.

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Karoon Lines Up Semisub Transocean Legend

- Karoon Lines Up Semisub Transocean Legend

Thursday, September 08, 2011
Karoon Gas Australia Ltd.

A drilling contract has been signed with Sedco Forex on Sept. 8 securing the Transocean Legend semi-submersible drilling rig to complete the planned Phase-2 Browse Basin exploration drilling program in the WA-314-P, WA-315-P and WA-398-P permits jointly held by ConocoPhillips and Karoon Gas. The contract comprises five firm wells (fulfilling permit commitments) with options for three additional wells (5-8 wells). Drilling is expected to commence in the fourth quarter of 2011 and is estimated to run for eighteen months to two years ConnocoPhillips is the operator of the jointly held WA-314-P, WA-315-P and WA-398-P Browse Basin permits containing the previously announced Poseidon and Kronos gas discoveries.

The five to eight well drilling program will target the Poseidon trend as well as surrounding prospects, including one prospect in WA-314-P late in the program.

The first well will be be Boreas-1, a crestal well in WA-315-P on a large tilted fault block east of the Poseidon-1 fault block. The results of the drilling campaign will allow the size and quality of the hydrocarbon accumulations within the exploration permits to be determined in preparation for a development decision. Karoon believes that the additional new prospects identified are of sufficient size that, if successful, would result in a meaningful increase in the capacity and economics of an eventual LNG project.

Pursuant to the 2006 Farm-in Agreement between Karoon and ConocoPhillips (Browse Basin) Pty Ltd, ConocoPhillips will be funding 80% of the drilling and testing costs for the initial $125 million of expenditure within WA-315-P.

Based on current forecasted costs Karoon will have sufficient capital at its disposal to complete all drilling activities for the planned program. Karoon is currently well advanced in the process of completing the farmout of its Santos Basin and Peruvian assets, and expects to have reduced financial exposure to both drilling campaigns. A list of potential farm-in partners will be shortlisted in the near future and negotiations are continuing.

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TGS, Fugro Team Up in Greenland Survey

- TGS, Fugro Team Up in Greenland Survey

Tuesday, September 06, 2011
TGS-NOPEC Geophysical Co. ASA

TGS has commenced a new 1,000 km multi-client 2D survey in Northeast Greenland in partnership with Fugro.

This survey will enable customers to prepare for the announced Greenland Licensing Round in 2012/2013 and will significantly add to a data set that TGS has been growing since 2008 in this promising region. After this year's data acquisition, TGS will be able to offer approximately 4,500 km of new multi-client 2D data, a large volume of reprocessed multi-client 2D data and full coverage of aeromagnetic/gravity data over the basins that are to be included in the planned licensing round.

The new seismic data is being acquired by the M/V Akademik Shatskiy supported by the ice breaker M/V Fennicia and is scheduled to complete during 4Q 2011. Data processing will be performed by TGS and data will be available to clients during 1Q 2012.

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Commodity Corner: Crude Up on Weather Threat

- Commodity Corner: Crude Up on Weather Threat

Thursday, September 01, 2011
Rigzone Staff
by Saaniya Bangee

Despite shaky equities and a rising dollar, crude futures inched modestly higher Thursday on weather reports of a storm brewing in the Gulf of Mexico.

October oil added 12 cents to its final price tag, settling at $88.93 a barrel on the New York Mercantile Exchange. Oil traded as low as $88.21 a barrel after an earlier intraday peak of $89.90.

The National Hurricane Center reported an 80 percent chance that a tropical wave in the Gulf of Mexico could develop into a tropical cyclone within the next 48 hours. Oil majors such as Shell, ExxonMobil, BP, Anadarko and BP have evacuated nine platforms in the Gulf of Mexico and shut in nearly 80,000 barrels of oil production, according to the Bureau of Ocean Energy Management, Regulation and Enforcement. In addition, 127 million cubic feet per day of natural gas was also shut in.

In other forecasts, initial unemployment claims fell by 12,000 to 409,000 last week. Data reported by the Labor Department helped boost optimism about the economy.

Brent crude, which is used to price many international oil varieties, lost 56 cents to settle lower at $114.29 barrel on fresh concerns over Greece's debt problems. The intraday range for Brent was $113.89 to $115.31 a barrel on the ICE future exchange.

Natural gas for October delivery remained unchanged at $4.05 per thousand cubic feet Thursday.

Gasoline gained 1.64 cents for the first trading session for the October contract. Reformulated gasoline settled at $2.89 a gallon. Some East Coast refineries remain shut down due to Hurricane Irene. Prices fluctuated between $2.85 and $2.92 Thursday.

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GM Reports Sales In August Were Up

 - GM Reports Sales In August Were Up



Sep 1, 2011

General Motors (NYSE:GM) reported that U.S. August sales were up to 18% to 218,479 units.

The company also said that the month-end dealer inventory in the United States was 556,884 units, including 212,520 full-size pick up trucks and it's on track to meet its target of ending 2011 with a full-size pick up inventory of 200,000 units.

General Motors (NYSE:GM) has a potential upside of 75.6% based on a current price of $23.41 and an average consensus analyst price target of $41.12.

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Oil Spill Safety Bill Fails, Supporters Vow to Bring It Up Again

- Oil Spill Safety Bill Fails, Supporters Vow to Bring It Up Again

Wednesday, August 31, 2011
San Jose Mercury News, Calif.
by Paul Rogers

With the state agency that regulates oil tanker safety facing potential layoffs, a bill to raise the fee that oil companies pay to fund California's oil spill safety programs failed Tuesday in the state Senate.

The bill, a priority for environmental groups, has been staunchly opposed by BP PLC and the Western States Petroleum Association.

"We're not done," said Assemblyman Jared Huffman, D-San Rafael, the measure's author. "The fat lady hasn't sung. We still have a week and a half to bring it back."

The bill, AB 1112, already has passed the Assembly and needed 21 votes Tuesday to move to the governor's desk. But it failed, achieving 17 votes, with 14 senators voting no and nine not voting.

The bill would increase the fee that oil companies pay from 5 cents per barrel to 6.75 cents per barrel over the next three years. The money raises $25 million a year and provides the bulk of the budget for the state Office of Spill Prevention and Response, an arm of the state Department of Fish and Game.

State lawmakers passed the fee in 1990 after the Exxon Valdez spill to increase California's oil safety efforts. Since then, the amount of oil spilled into state waters has fallen by 95 percent. The money has funded emergency drills, tougher oversight of tankers and terminals, and scientific studies of oiled wildlife. Since the original fee passed, at 4 cents a barrel, it has been raised once, in 2002.

Capt. Scott Schaefer, administrator of the state oil spill agency, said that because of costs associated with new laws passed after the 2007 Cosco Busan oil spill in San Francisco Bay, the fund will be $5 million in deficit by 2013 without an increase.

Huffman said he will bring the bill up again before the end of the legislative session, Sept. 9. All 17 who voted for the bill were Democrats. Twelve of the 14 no votes were from Republicans, many of whom oppose increasing state fees and taxes. Environmental groups were surprised that several senators from coastal areas did not vote, including Sen. Leland Yee, of San Francisco; Juan Vargas, of San Diego; Curren Price and Alex Padilla, of Los Angeles; and Sam Blakeslee, whose district extends from San Luis Obispo along Monterey Bay to south San Jose.

"Sen. Yee supports the bill," said his spokesman Adam Keglin afterward. "He was off the floor at the time. It will come back up, and he'll vote for it as is."

Copyright (c) 2011 the San Jose Mercury News (San Jose, Calif.)

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Lukoil Reports $3.25B in 2Q Earnings, Up 67%

- Lukoil Reports $3.25B in 2Q Earnings, Up 67%

Wednesday, August 31, 2011
OAO Lukoil Holdings

LUKOIL has published consolidated US GAAP financial statements for the second quarter and first half of 2011.

The Company's net income was $6.768 billion in the first half of 2011, which is 69.1% higher y-o-y, including $3.251 billion in the second quarter. EBITDA in the first half of 2011 was $10.688 billion, which is 43.8% higher y-o-y. Sales revenues were $64.538 billion (+29.7% y-o-y). Positive dynamics of our financial results was mainly due to increase in hydrocarbon prices and refining margin in the first half of 2011 compared to the respective period of 2010.

Capital expenditures including non-cash transactions in the first half of 2011 were $3.6 billion, which is 13.3% higher y-o-y. The Company's strict financial discipline helped to generate high free cash flow which reached $4,714 million in the first half of 2011 compared to $3,127 million in the first half of 2010.

In the first half of 2011, lifting costs per boe of production were $4.72, which is 17.4% higher y-o-y. The growth was mainly due to the real ruble appreciation, which was 15.0% in the first half of 2011.

In the first half of 2011, LUKOIL Group total hydrocarbon production available for sale reached 2,162 th. boe per day, which is a 4.4% decrease y-o-y.

In the first half of 2011 throughputs at the Company's refineries (including its share in crude oil and petroleum product throughput at the ISAB and TRN refining complexes) decreased by 1.2% y-o-y and reached 32.03 MM tonnes. Throughputs at the Company's refineries in Russia increased by 1.5% y-o-y, throughputs at the Company's international refineries decreased by 6.9% y-o-y due to shutdown of the Odessa Refinery because of unfavorable economic conditions in the first half of 2011.

Measures aimed at higher efficiency and cost control allowed the Company to generate strong free cash flow and increase net income.

Also, an extended meeting of the OAO LUKOIL Board of Directors was held on Wednesday. The meeting considered the Company's production and financial performance and the investment program implementation results in the first half of 2011.

In his address to the meeting, LUKOIL President Vagit Alekperov specified the need to develop a Hydrocarbon Production Stabilization Program and to rigorously implement it.

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Exxon Mobil and Rosneft Team Up

- Exxon Mobil and Rosneft Team Up



Aug 30, 2011

Exxon Mobil (NYSE:XOM) and Rosneft teamed up with U.S. company ExxonMobil to develop Russian Arctic oil fields, that had eluded BP earlier this year.

Rustam Kazharov, a spokesman for Rosneft told the Associates Press the deal was signed Tuesday in the presence of Russia's Prime Minister Vladimar Putin.

Rosneft struck a deal with BP in January to jointly increase Russia's Arctic but the deal fell through after BP's Russian shareholders managed to block the deal.

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Total Starts Up Taps at Pazflor Field

- Total Starts Up Taps at Pazflor Field

Friday, August 26, 2011
Total
by SubseaIQ

Total, operator of Block 17, announced that the giant Pazflor field offshore Angola has come on stream ahead of the initial schedule. The Pazflor field lies 150 kilometers off Luanda in water depths ranging from 600 to 1,200 meters and has estimated proved and probable reserves of 590 million barrels. The field will gradually ramp up to its full production capacity of 220,000 barrels per day over the coming months.

"Pazflor's start-up, several weeks ahead of schedule and within budget, is a remarkable achievement of the teams involved. The support and trust of Sonangol, our concession holder and partner, also made an invaluable contribution to our efficiency," said Yves-Louis Darricarrère, President Exploration & Production at Total. "Pazflor required a development effort on the same scale as the field. Paving a way with new technologies, the project showcases Total's expertise in highly complex environments. The project facilities have been designed and thoroughly tested in accordance with the strictest health, safety and environmental standards. This is another step in the ongoing saga of our deep offshore feats, begun right here in Angola. Deepwater developments are a core driver of our future production growth."

Pazflor comprises a vast subsea gathering network, the most complex ever built in Angola: 180 kilometers of lines tying in 49 subsea wells, 10,000 metric tons of subsea equipment and the giant Pazflor floating production, storage and offloading (FPSO) vessel. Held in position by 16 subsea mooring connectors, with its 325 meters long, 62 meters wide and a weight of more than 120,000 metric tons, the FPSO is the largest in the world. It can store up to 1.9 million barrels of oil that is then exported to tankers via an offloading buoy. The associated gas is reinjected into the reservoir, but could also be exported to the Angola LNG plant once the latter becomes operational.

A key technical challenge was producing two very different grades of oil from four separate reservoirs. Producing the heavy, viscous oil from the three Miocene reservoirs, which account for two-thirds of the reserves, and the related flow assurance constraints, represented a major challenge. The gas has to be separated from the liquids on the seabed so that the viscous liquids can then be pumped to the surface. The design and installation of subsea gas-liquid separation units and pumps are a world first on this scale. The pumps were purpose designed and tested for Pazflor.

Total's wholly owned subsidiary Total E&P Angola operates Block 17, with a 40% interest, while Sonangol is the concession holder. The other partners are Statoil ASA (23.3%), Esso Exploration Angola (Block 17) Limited (20%) and BP Exploration (Angola) Ltd (16.67%).

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Petrofac Touts $2.71B in Revenue, Up 25%

- Petrofac Touts $2.71B in Revenue, Up 25%

Monday, August 22, 2011
Petrofac Ltd.

Petrofac announced its interim results for the six months ended June 30, 2011.

FINANCIAL HIGHLIGHTS

• Revenue up 25.2% to US $2,711.1 million (2010 restated: US $2,165.8 million)
• Net profit up 6.6% to US $246.3 million (2010 restated: US $231.0 million)
• Earnings per share (diluted) up 6.7% to 71.84 cents (2010 restated: 67.31 cents)
• Interim dividend up 26.1% to 17.40 cents (10.54 pence) per share (2010: 13.80 cents)
• Backlog US $11.4 billion at 30 June 2011 (December 31, 2010: US $11.7 billion; 30 June 2010: US $6.9 billion)
• Gross cash balances at 30 June 2011 of US $1.8 billion (December 31, 2010: US $1.1 billion)

Ayman Asfari, Petrofac's group chief executive commented on the interim results:

"We have had a successful year to date, with good operational performance across our portfolio of projects and encouraging progress against our recently announced Integrated Energy Services strategy. We are well on course to deliver like-for-like net profit growth in 2011 of at least 15% and in-line with current market expectations.

"With a strong financial position, a differentiated and competitive offering and a proven track record in project execution, we remain confident of achieving our medium-term growth target of more than doubling our recurring 2010 earnings by 2015."

OPERATIONAL HIGHLIGHTS

Engineering & Construction

• Order intake in the year to date of US $1.6 billion with new awards in Algeria, Iraq and Malaysia
• Good progress on South Yoloten development, in Turkmenistan: substantially completed construction of temporary facilities and placed the majority of orders for procurement items
• Completed the Jihar gas plant in Syria and the In Salah Gas compression facilities and power generation in Algeria Offshore Engineering & Operations
• Secured a number of new contracts and extensions, including a contract to provide maintenance services on the Rumaila oilfield in Iraq for BP
• Record activity, including on the SEPAT development and upgrade of the FPSO Berantai (formerly the East Fortune) in Malaysia (both being undertaken jointly with E&C)

Engineering, Training Services and Production Solutions

• Opened a third Indian office, in Delhi, to support growth in activity levels across the group
• Entered into an MOU for a technical training partnership with PETRONAS to develop competency-based training for operations and maintenance personnel in Malaysia
• Good progress on Ticleni in Romania, improving production through optimising pump settings, working over wells and bringing back on-stream the first five of many shut-in wells
• Agreed to invest up to a further US $75 million in Seven Energy taking our interest up to 24.5%
• Selected bidder on Magallanes and Santuario Production Enhancement Contracts in Mexico

Energy Developments

• Secured first Risk Service Contract (RSC) in Malaysia, for development of the Berantai field
• Acquired FPF3 (formerly the Jasmine Venture), deployed on the Jasmine field in the Gulf of Thailand and leased to Pearl Energy, a subsidiary of Mubadala, and now operated by Offshore Engineering & Operations
• Pre-invested in field infrastructure in readiness for future developments, including the acquisition of FPF4 (formerly the Cossack Pioneer)
• Cendor phase 2 in Block PM304, offshore Malaysia, progressing to schedule and entered into an MOU with PETRONAS to accelerate the third phase of Block PM304, West Desaru

OUTLOOK

We are confident that we can continue the good progress that we have achieved in Engineering & Construction in the year to date. With high levels of backlog, we have outstanding revenue visibility which should ensure that we report strong growth in our full year revenues and we expect full year net margins to be in line with our medium-term guidance at around 11%.

While Offshore Engineering & Operations activity levels and revenues are expected to continue at record levels, net profit is expected to be lower in the second half of the year, as the first half benefited from significant progress on the SEPAT development and a provision release following completion of a long-term maintenance services contract. Net margins for the full year are expected to be substantially higher than in the prior year.

The second half performance of the Engineering, Training Services and Production Solutions reporting segment is expected to be broadly in line with the first half of the year, albeit with a greater contribution from Production Solutions, as we expect a general improvement in our consultancy and technology businesses and a positive contribution from the Ticleni Production Enhancement Contract.

In Energy Developments, our operational assets are expected to continue to perform broadly in line with the first half, with the exception of the Ohanet RSC, which ends, as expected, in October. On the Berantai field development, we expect the FPSO Berantai to mobilize to the field in early 2012, with first gas from the field expected shortly thereafter.

With a strong financial position, a differentiated and competitive offering and a proven track record in project execution, we are confident that we will continue to deliver superior value for our customers and sector-leading returns for our shareholders.

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Halliburton Wraps Up 1st HZ Shale Well in Argentina for Apache

- Halliburton Wraps Up 1st HZ Shale Well in Argentina for Apache

Thursday, August 18, 2011
Halliburton Co.

Halliburton has successfully executed the first horizontal, multistage hydraulic fracture shale gas completion in Argentina's Neuquén Basin for Apache. Halliburton provided all major well construction and completion services for the project, resulting in the successful delivery of South America's first horizontal and deepest shale gas well.

As global development of unconventional resources materialize, Halliburton is in the process of pre-positioning Unconventional Reservoir Solutions Teams around the world. These teams draw upon the extensive knowledge and experience garnered from Halliburton's unrivalled position in North America's unconventional reservoir development. Halliburton, chosen by Apache because of its Buenos Aires-based Unconventional Reservoir Solutions Team's expertise and understanding of the specific complexities of the Los Molles shale formation, placed 10 hydraulic fracture stages in the horizontal section at a depth of over 4,400 meters.

"Halliburton's ability to apply its expertise globally will assist operators to efficiently develop frontier unconventional reservoirs," said Roberto Munoz, vice president, Latin America Region, Halliburton. "With the third largest estimated unconventional reserves after China and the United States, Argentina's shale gas potential will benefit greatly from the application of these technologies."

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Chevron Lines Up Atwood Semisub

- Chevron Lines Up Atwood Semisub

Tuesday, August 16, 2011
Atwood Oceanics Inc.

Atwood Oceanics announced that one of its subsidiaries has been awarded a six month contract by Chevron Australia Pty. Ltd. for the Atwood Eagle. With this contract, the firm contractual commitments for the Atwood Eagle are expected to extend through July 2012. The day rate will be approximately $370,000.

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Gulf Keystone Bumps Up Resources at Sheikh Adi

- Gulf Keystone Bumps Up Resources at Sheikh Adi

Wednesday, August 10, 2011
Gulf Keystone Petroleum Ltd.

Gulf Keystone announced results of an independent preliminary evaluation of the Sheikh Adi resources by Dynamic Global Advisors (DGA), independent Houston-based exploration consultants.

The DGA report, based on Sheikh Adi-1 wireline logging data, core samples, 2D and 3D seismic and regional data, has indicated a significant range of between 1 billion barrels and 3 billion barrels of gross oil-in-place volumes calculated on the P90 to P10 basis, with a P50 estimate of 1.9 billion barrels.

Gulf Keystone has completed drilling of Sheikh Adi-1, the first exploration well to be drilled on the Sheikh Adi structure, to a TD (total depth) of 3,780 meters in the Triassic zone. A series of flow tests will now be performed on a number of Jurassic zones in the Sheikh Adi-1 well. Testing in the Triassic zone will not be possible due to issues relating to casing integrity at these depths.

The Sheikh Adi block is located immediately to the west of the Company's Shaikan block, where a major discovery was made in 2009. Gulf Keystone is the Operator of the Sheikh Adi block with an 80 percent working interest and is carrying the Kurdistan Regional Government's 20 percent working interest in the block.

DGA's previous assessments of assets on behalf of Gulf Keystone included independent evaluation of the Shaikan discovery, including a major revision of the gross oil-in-place volumes (4.9 billion barrels to 10.8 billion barrels calculated on the P90 to P10 basis) announced in April 2011.

John Gerstenlauer, Gulf Keystone's Chief Operating Officer commented, "This independent report demonstrates the potential of the Sheikh Adi block with between 1 and 3 billion barrels of gross oil-in-place. This report reinforces our belief in having encountered yet another potential world class oil source. We plan to further evaluate the Sheikh Adi structure and define and assess this complicated geological structure. The Sheikh Adi oil-in-place numbers are all the more significant due to our 80 percent interest in the block. These numbers are in addition to 7.5 billion barrels of P50 oil-in-place at Shaikan, 2.4 billion barrels of P50 oil-in-place at Akri-Bijeel and 1.9 billion barrels of estimated petroleum-initially-in-place at Ber Bahr. This report further demonstrates the world class nature of Gulf Keystone's assets in the Kurdistan Region of Iraq".

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Guv Fills Up O&G Commission

- Guv Fills Up O&G Commission

Monday, August 01, 2011
The Pueblo Chieftain, Colo.
by Patrick Malone

Gov. John Hickenlooper announced eight appointments Friday to the Colorado Oil and Gas Conservation Commission. Two are reappointments.

Republicans criticized the omission of representation from the Eastern Plains, but expressed optimism that Hickenlooper's appointees will be more friendly to the oil and gas industry than the commission was under former Gov. Bill Ritter.

"There is no representation on there from Eastern Colorado," said Rep. Jon Becker, R-Fort Morgan, whose district includes parts of Southeastern Colorado. "Without representation from Eastern Colorado, we leave out a whole region of the state that is very important to oil and gas. The governor overlooked that. He should have made at least one appointment from the Eastern Plains. There are plenty of qualified people there to serve on this commission," Becker said.

Hickenlooper has often said he supports common-sense changes to regulation of the oil and gas industry in Colorado. A favorite example of the governor's is the water-treatment rule that many ranchers and gas companies agree creates unnecessary expense for drilling operations in the Raton Basin near Trinidad.

Becker said he is optimistic the new commission will tackle regulations with an eye on spurring business and be more mindful of the economic impact of its decisions than the commission was under Ritter.

Environmental groups said they will keep a watchful eye on the new commission.

"Gov. Hickenlooper has repeatedly said he would 'strike the right balance' in overseeing the oil and gas industry," said Elise Jones, executive director of the Colorado Environmental Coalition. "The jury is still very much out as to whether this set of appointments meets that important standard or whether instead the balance has shifted away from protecting Colorado's air, water, wildlife and communities from the impact of drilling."

Hickenlooper said he feels assured that his mix of appointees will address the competing interests of business and the environment.

"Different voices and a united spirit of collaboration are key to the success of the commission," the governor said. "We are confident this group will serve the industry, land owners and the environment well as it navigates through issues that are important to both the state's economy and the protection of Colorado's beautiful landscapes."

Hickenlooper appointed eight new commissions to replace those whose terms expired July 1. The appointees are subject to Senate confirmation. Their four-year terms expire July 1, 2015.

Copyright (c) 2011, The Pueblo Chieftain, Colo.

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Dominion Petroleum Picks Up Block Offshore Kenya

- Dominion Petroleum Picks Up Block Offshore Kenya

Monday, August 01, 2011
Dominion Petroleum Ltd.

Dominion Petroleum announced the award of Block L15 of the Lamu Basin, offshore Kenya. This new award follows Dominion having secured Block L9, offshore Kenya, in March 2011.

The Company concluded negotiations with the Government of the Republic of Kenya by executing heads of agreement ("HoA") which define the terms for Block L15, with Dominion serving as operator with a 100% working interest.

The award of L15 is subject only to the signature of a Production Sharing Contract ("PSC") by Dominion and Kenya's Ministry of Energy; currently scheduled to take place in the coming weeks in Nairobi.

With Block L15 now added to its portfolio of exploration assets in offshore East Africa, Dominion holds a leading exploration portfolio in the deepwater East African margin by now operating 3 blocks in Tanzania and Kenya. The directors anticipate that the expanded, combined portfolio may gain even more industry interest going forward. The Company can now adopt a partnering strategy for the assets in terms of moving toward the drilling of this expanded portfolio.

Block L15 lies immediately to the north of Block L8, where the reportedly 1 billion barrel Mbawa prospect shall likely be drilled in mid 2012. Dominion's new Block is on the Davy-Walu structural trend, as is Block L9. The only well in Block L15 is Kofia-1, which was drilled by Union Oil in 1985 and encountered good oil shows in the Palaeogene and Upper Cretaceous intervals. Planned drilling by other operators along the Davy-Walu trend over the next 12 months may serve to de-risk the prospectivity in both L9 and L15 before firm drilling commitments are made in either PSC.

Following signature, the Initial Exploration Period of the PSC will last for two years. During this time, a gross minimum work commitment of $2.85m inclusive of the acquisition of 250 square kilometres of 3D seismic data is required.

Following the Initial Exploration Period, there is an option to relinquish the PSC or commit to another two year exploration period with the obligation to drill one well in that period.

The terms and the commitments for L15 defined in the HoA compare very favorably to other countries in the region relative to the potential resource the block represents.

Andrew Cochran, Chief Executive of Dominion Petroleum, commented, "We are delighted to add Block L15 to Dominion's East Africa deepwater exploration portfolio, one of the most sought after addresses in the exploration industry these days. The region is seeing both growing attention from, and accelerated activity by, major players with Kenya now due for deepwater drilling within the next year following the last year's successes in Tanzania and Mozambique.

"Dominion's new award represents a material expansion of an already enviable deepwater East African portfolio. We can now focus our attentions on the business of exploring these blocks, realizing their true value and embarking on substantive discussions with potential partners to establish plans for drilling."

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ExxonMobil Reports $10.7B in 2Q11, Up 41%

- ExxonMobil Reports $10.7B in 2Q11, Up 41%

Thursday, July 28, 2011
ExxonMobil Corp.

ExxonMobil announced its estimated second quarter 2011 results.

ExxonMobil's Chairman Rex W. Tillerson commented, "ExxonMobil recorded strong results during the second quarter of 2011, while investing at a record level of over $10 billion to develop new supplies of energy to meet growing world demand.

"Second quarter earnings of $10.7 billion were up 41% from the second quarter of 2010, reflecting higher crude oil and natural gas realizations, improved Downstream results and continued strength in Chemicals. First half 2011 earnings of $21.3 billion increased 54% over the first half of 2010.

"In the second quarter, capital and exploration expenditures were a record $10.3 billion, up 58% from the second quarter of 2010.

"Oil-equivalent production increased by 10% over the second quarter of 2010, driven by our world-class assets in Qatar and our growing unconventional gas portfolio.

"The Corporation returned over $7 billion to shareholders in the second quarter through dividends and share purchases to reduce shares outstanding."

SECOND QUARTER HIGHLIGHTS

• Earnings were $10,680 million, an increase of 41% or $3,120 million from the second quarter of 2010.
• Earnings per share were $2.18, an increase of 36%.
• Capital and exploration expenditures were a record $10.3 billion, up 58% from the second quarter of 2010.
• Oil-equivalent production increased 10% from the second quarter of 2010. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, production was up over 12%.
• Cash flow from operations and asset sales was $14.4 billion, including asset sales of $1.5 billion.
• Share purchases to reduce shares outstanding were $5 billion.
• Dividends per share of $0.47 increased by 7% compared to the second quarter of 2010.
• Announced two major oil discoveries and a gas discovery in the deepwater Gulf of Mexico after drilling the company's first post-moratorium deepwater exploration well.
• Concluded the acquisitions of two Phillips companies, nearly doubling our Marcellus acreage footprint to more than 700,000 net acres.

Second Quarter 2011 vs. Second Quarter 2010

Upstream earnings were $8,541 million, up $3,205 million from the second quarter of 2010. Higher liquids and natural gas realizations increased earnings by $3.6 billion. Production mix and volume effects decreased earnings by $480 million.

On an oil-equivalent basis, production increased 10% from the second quarter of 2010. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, production was up over 12%.

Liquids production totaled 2,351 kbd (thousands of barrels per day), up 26 kbd from the second quarter of 2010. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, liquids production was up 4%, as increased production in Qatar, the U.S. and Iraq more than offset field decline.

Second quarter natural gas production was 12,267 mcfd (millions of cubic feet per day), up 2,242 mcfd from the second quarter of 2010, driven by additional U.S. unconventional gas volumes and project ramp-ups in Qatar.

Earnings from U.S. Upstream operations were $1,449 million, $584 million higher than the second quarter of 2010. Non-U.S. Upstream earnings were $7,092 million, up $2,621 million from last year.

Downstream earnings of $1,356 million were up $136 million from the second quarter of 2010. Margins increased earnings by $60 million. Positive volume and mix effects increased earnings by $150 million, while all other items decreased earnings by $70 million. Petroleum product sales of 6,331 kbd were 27 kbd higher than last year's second quarter.

Earnings from the U.S. Downstream were $734 million, up $294 million from the second quarter of 2010. Non-U.S. Downstream earnings of $622 million were $158 million lower than last year.

Chemical earnings of $1,321 million were $47 million lower than the second quarter of 2010. Improved margins increased earnings by $120 million, while lower sales volumes decreased earnings by $90 million. Other items, mainly unfavorable tax effects, decreased earnings by $80 million. Second quarter prime product sales of 6,181 kt (thousands of metric tons) were 315 kt lower than last year's second quarter.

Corporate and financing expenses were $538 million, up $174 million from the second quarter of 2010 due to the absence of favorable 2010 tax items.

During the second quarter of 2011, Exxon Mobil Corporation purchased 67 million shares of its common stock for the treasury at a gross cost of $5.5 billion. These purchases included $5 billion to reduce the number of shares outstanding, with the balance used to offset shares issued in conjunction with the company's benefit plans and programs. Share purchases to reduce shares outstanding are currently anticipated to equal $5 billion in the third quarter of 2011. Purchases may be made in both the open market and through negotiated transactions, and may be increased, decreased or discontinued at any time without prior notice.

First Half 2011 vs. First Half 2010

Earnings of $21,330 million increased $7,470 million from 2010. Earnings per share increased 47% to $4.32.

FIRST HALF HIGHLIGHTS

• Earnings were $21,330 million, up 54%.
• Earnings per share increased 47% to $4.32.
• Oil-equivalent production was up 10% from 2010. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, production was up 12%.
• Cash flow from operations and asset sales was $32.6 billion, including asset sales of $2.8 billion.
• The Corporation distributed over $14 billion to shareholders in the first half of 2011 through dividends and share purchases to reduce shares outstanding.
• Capital and exploration expenditures were a record $18.1 billion, up 35% from the first half of 2010.

Upstream earnings were $17,216 million, up $6,066 million from 2010. Higher crude oil and natural gas realizations increased earnings by $6.2 billion. Production mix and volume effects decreased earnings by $710 million, while all other items, mainly gains from asset sales, increased earnings by $600 million.

On an oil-equivalent basis, production was up 10% compared to the same period in 2010. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, production was up 12%.

Liquids production of 2,375 kbd increased 5 kbd compared with 2010. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, liquids production was up 3%, as higher volumes from Qatar and the U.S. more than offset field decline.

Natural gas production of 13,390 mcfd increased 2,538 mcfd from 2010, driven by additional U.S. unconventional gas volumes and project ramp-ups in Qatar.

Earnings from U.S. Upstream operations for 2011 were $2,728 million, an increase of $772 million. Earnings outside the U.S. were $14,488 million, up $5,294 million.

Downstream earnings of $2,455 million increased $1,198 million from 2010. Margins increased earnings by $510 million. Positive volume and mix effects increased earnings by $520 million, while all other items, mainly favorable foreign exchange effects, increased earnings by $170 million. Petroleum product sales of 6,299 kbd increased 49 kbd from 2010.

U.S. Downstream earnings were $1,428 million, up $1,048 million from 2010. Non-U.S. Downstream earnings were $1,027 million, $150 million higher than last year.

Chemical earnings of $2,837 million were $220 million higher than 2010. Stronger margins increased earnings by $470 million, while lower volumes decreased earnings by $60 million. Other items, including unfavorable tax effects and higher maintenance expenses, decreased earnings by $190 million. Prime product sales of 12,503 kt were down 481 kt from 2010.

Corporate and financing expenses were $1,178 million, up $14 million from 2010.

Gross share purchases through the first half of 2011 were $11.2 billion, reducing shares outstanding by 136 million shares.

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OXY 2Q Earnings Up 17%

- OXY 2Q Earnings Up 17%

Tuesday, July 26, 2011
Occidental Petroleum Corp.

Occidental Petroleum Corporation announced core income of $1.8 billion ($2.23 per diluted share) for the second quarter of 2011, compared with $1.1 billion ($1.32 per diluted share) for the second quarter of 2010. Net income was $1.8 billion ($2.23 per diluted share) for the second quarter of 2011, compared with $1.1 billion ($1.31 per diluted share) for the second quarter of 2010.

In announcing the results, Stephen I. Chazen, President and Chief Executive Officer, said, "The second quarter 2011 net income of $1.8 billion was an increase of 17 percent over the first quarter results. Improved earnings in all of our business segments resulted in a six month, year-to-date cash flow from operations of $5.6 billion and an annualized return on equity of 20 percent. Our second quarter domestic oil and gas production grew 11 percent from the second quarter of the prior year to 424,000 BOE per day."

QUARTERLY RESULTS

Oil and Gas

Oil and gas segment earnings were $2.6 billion for the second quarter of 2011, compared with $1.9 billion for the same period in 2010. The increase in the second quarter of 2011 earnings was due mainly to higher crude oil prices.

For the second quarter of 2011, daily oil and gas production volumes averaged 715,000 barrels of oil equivalent (BOE), compared with 701,000 BOE in the second quarter of 2010. As a result of higher year-over-year average oil prices and other factors affecting production sharing and similar contracts, production was reduced in the Middle East/North Africa and Colombia by 11,000 BOE per day, with another 1,000 BOE per day reduction at THUMS in Long Beach.

The second quarter 2011 production volume increase was a result of 42,000 BOE per day higher domestic volumes, partially offset by reduced volumes in the Middle East / North Africa. The domestic increase was mainly from the new acquisitions in South Texas and the North Dakota Williston Basin. The Middle East/North Africa was lower primarily due to the lack of production in Libya and price impacts on production sharing contracts, partially offset by production from Iraq coming on line in 2011 and higher volumes from the Mukhaizna field in Oman.

Daily sales volumes remained flat at 705,000 BOE per day in the second quarter of 2011, compared with 705,000 BOE per day in the second quarter of 2010. The 2011 sales volumes were lower than the production volumes due to the timing of liftings in Iraq, Qatar and Oman.

Second quarter realized prices improved for all products on a year-over-year basis. The price for worldwide crude oil was $103.12 per barrel for the second quarter of 2011, compared with $74.39 per barrel for the second quarter of 2010. The second quarter of 2011 realized oil price represents 101 percent of the average WTI price for the quarter. Worldwide NGL prices were $57.67 per barrel in the second quarter of 2011, compared with $44.08 per barrel in the second quarter of 2010. Domestic gas prices increased from $4.19 per MCF in the second quarter of 2010 to $4.27 per MCF for the second quarter of 2011.

SIX-MONTH RESULTS

Year-to-date 2011 core results were over $3.4 billion ($4.19 per diluted share), compared with $2.2 billion ($2.67 per diluted share) for the same period in 2010. Net income for the first six months of 2011 was $3.4 billion ($4.13 per diluted share), compared with $2.1 billion ($2.61 per diluted share) for the same period in 2010.

Oil and Gas

Oil and gas segment earnings were $5.1 billion for the six months of 2011, compared with $3.7 billion for the same period of 2010. The $1.4 billion increase in the 2011 results reflected higher crude oil and NGL prices and higher sales volumes, partially offset by higher operating costs and DD&A rates.

Daily oil and gas production volumes for the six months were 723,000 BOE per day for 2011, compared with 701,000 BOE per day for the 2010 period. Higher year-over-year average oil prices and other factors affecting our production sharing and similar contracts lowered our Middle East/North Africa, Long Beach and Colombia production by 14,000 BOE per day.

Domestic volumes increased primarily due to new operations in South Texas and the Williston Basin, partially offset by lower gas volumes in California. The Middle East/North Africa's production declined due to impacts of price and other factors on production sharing contracts, lower production in Libya and planned maintenance in Dolphin. Partially offsetting these declines were increases from the new production in Iraq and higher production in the Mukhaizna field in Oman.

Daily sales volumes were 717,000 BOE in the first six months of 2011, compared with 695,000 BOE for 2010.

Oxy's realized prices improved for crude oil and NGLs but declined for natural gas on a year-over-year basis. Worldwide crude oil prices were $97.38 per barrel for the six months of 2011, compared with $74.24 per barrel for the six months of 2010. Worldwide NGL prices were $55.38 per barrel for the six months of 2011, compared with $45.73 per barrel in the six months of 2010. Domestic gas prices declined from $4.90 per MCF in the six months of 2010 to $4.24 per MCF in the six months of 2011.

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BP Scoops Up Blocks Offshore Trinidad

- BP Scoops Up Blocks Offshore Trinidad

Monday, July 25, 2011
BP plc

BP has been awarded two deepwater exploration and production blocks by the Government of the Republic of Trinidad and Tobago.

BP was awarded a 100 percent interest in blocks 23(a) and TTDAA 14, both in deepwater frontier acreage offshore Trinidad's east coast, under production sharing contracts.

The success follows detailed subsurface research and evaluation by BP whose Trinidad operations account for more than half of Trinidad and Tobago's natural gas output and 12 percent of BP's global oil and gas production. The awards will double the acreage held by BP controlled companies in Trinidad and Tobago.

"BP has a long history and major business in Trinidad and Tobago, and we are keen to participate in the next phase of exploring the country's resources," said Bob Dudley, BP group chief executive. "These awards mean BP has gained access to 31 new upstream blocks across the world since July last year, a significant step up in new access.

"Increasing our efforts in exploration and applying our deepwater experience and expertise to new basins around the world is a key part of BP's strategy to deliver long-term value growth. We are pleased to see the confidence that governments across the world have placed in BP to carefully explore and develop resources."

Since July 2010 BP has gained new exploration access in Azerbaijan, Brazil, Indonesia, Australia, the UK and China. In addition, BP reached agreement in February with Reliance Industries to take a 30 percent interest in 23 oil and gas licences offshore India.

"BP is very pleased to be given this opportunity to be pioneers as we work to unlock Trinidad's deepwater potential using the best in class technology and expertise, potentially bringing additional benefits from our existing business and infrastructure," added BP Trinidad and Tobago regional president Norman Christie. "The decision to participate in this bid round demonstrates BP's long term commitment to Trinidad and Tobago."

Block 23(a), located approximately 300 kilometers north east of BP Trinidad and Tobago's (bpTT's) Galeota Point operations base, covers approximately 2,600 square kilometers in water depths averaging 2,000 meters. Block TTDAA 14 which is located next to block 23(a) covers a further 1,000 square kilometers in water depths averaging 2,000 meters.

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Sea Dragon to Ramp Up Production at NW Gemsa Concession

- Sea Dragon to Ramp Up Production at NW Gemsa Concession

Monday, July 25, 2011
Sea Dragon Energy Inc.

Sea Dragon provided the following update on its operations in Egypt.

NW Gemsa Concession

Al Amir SE#8 Well: The well was spud on May 20, 2011 and successfully drilled to its total depth of 10,750 ft. This is the second of four water injection wells planned for the Al Amir SE water secondary recovery project. Well logs indicate good quality sands in both the Kareem Shagar and Rahmi zones, well suited for water flooding purposes. Pressure measurements indicate that communication exists with other producers in the area. The well was successfully perforated on July 10(th) in the interval 10,404 to 10,432 ft within the Kareem Rahmi interval. The Kareem Shagar Formation will be perforated at a later date.

Geyad-5 Well: The Geyad-5 water injection well was spud on July 23(rd) , 2011 and is currently drilling below 400 ft. The well is expected to reach a total depth of 7,000 ft. and bottom in the Upper Rudeis Formation. This well is located approximately 1.1 km west-south west of Geyad-1X and 2 km of the recently drilled Geyad-3C well. It is targeting the Kareem Formation water leg in the western edge of the field.

Water injection is expected to commence in Q-4, 2011. This marks the beginning of the water flood project which will result in significant increase in recoverable reserves and production levels from the field.

Current production from the Al Amir SE and Geyad fields is running steady at around 8,000 bopd (800 bopd net to Sea Dragon). Cumulative production from the NW Gemsa Concession has now exceeded 5.6 million barrels of 42 degree API Crude oil.

Sea Dragon has a 10% working interest in the NW Gemsa Concession with Vegas at 50%, as operator, and Circle Oil PLC with 40%.

Kom Ombo Concession

Geological, geophysical and engineering work and studies are continuing. The work includes a remapping of the Al Baraka field and exploratory prospects. This work will be complemented by the results of other geotechnical studies now underway to firm up locations for the two exploratory wells and AB-16, AB-17 and AB-18 development wells planned for the fourth quarter, 2011.

Work is underway currently on securing a drilling rig and ancillary services to be mobilized to Kom Ombo and begin operations during the fourth quarter. All tubular and supplies have already been ordered and should be available within the next two months.

Production from the Al Baraka field is approximately 800 bopd (400 bopd net to Sea Dragon).

Sea Dragon has a 50% working Interest and is a joint operator of the Kom Ombo Concession with Dana Gas owning the remaining 50%.

Commenting on the latest developments on the Company's operations in Egypt, Company Chairman and CEO Mr. Said Arrata stated, "We are very pleased with the progress made on drilling the water injection wells in our NW Gemsa Concession. We are looking forward to the commencement of the water flood project and the resulting increase in production. In Kom Ombo, preparation work for the fall drilling season is well underway."

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Diamond Offshore 2Q Earnings Up 19%

- Diamond Offshore 2Q Earnings Up 19%

Thursday, July 21, 2011
Diamond Offshore Drilling Inc.

Diamond Offshore Drilling reported net income for the second quarter of 2011 of $266.6 million, or $1.92 per share on a diluted basis, compared with net income of $224.4 million, or $1.61 per share on a diluted basis, in the same period a year earlier. Revenues in the second quarter of 2011 were $889.5 million, compared with revenues of $822.6 million for the second quarter of 2010.

For the six months ended June 30, 2011, the Company reported net income of $517.2 million, or $3.72 per share on a diluted basis, compared with net income of $515.2 million, or $3.70 per share on a diluted basis, for the same period in 2010. Revenue for the six months ended June 30, 2011 was $1.7 billion, essentially identical with $1.7 billion for the first six months of 2010.

In addition, in the past 45 days the Company has put in place 10 new agreements that are expected to generate combined maximum total revenue of approximately $1 billion and represent over 14 years of contract drilling backlog. Significant among these agreements:

• Petrobras has given notice of its intent to exercise a right to convert the Ocean Baroness and Ocean Valor contracts from three years to five years, in return for which the Company will lower each dayrate by $10,000. The two rigs are expected to earn additional combined maximum total revenue of approximately $500 million, excluding any potential performance bonus payments.
• The Company has reached agreement with OGX to extend both the Ocean Quest and Ocean Star contracts in Brazil by one year. The extensions are expected to result in combined maximum total revenue of approximately $200 million.
• The Ocean Yorktown has received a letter of award for a 930-day contract with Pemex in Mexico commencing mid-November 2011 that is expected to earn maximum total revenue of approximately $171 million. The unit is currently under contract to Petrobras in Brazil, but under mutually agreed terms will demobe to Mexico as soon as practical. The remaining days of the Yorktown contract with Petrobras will be added to the Ocean Concord contract.
• The jack-up Ocean Summit has received a letter of award for a 985-day contract with Pemex in Mexico commencing in late February 2012 that is expected to earn maximum total revenue of approximately $85 million.
• The jack-up Ocean Titan has received a letter of award for a 777-day contract with Pemex in Mexico commencing in mid-November 2011 that is expected to earn maximum total revenue of approximately $80 million.

Diamond Offshore provides contract drilling services to the energy industry and is a leader in deepwater drilling.

Maximum contract revenue as stated above assumes 100% rig utilization. Generally, rig utilization rates approach 95-98% during contracted periods; however, utilization rates can be adversely impacted by additional downtime due to unscheduled repairs, maintenance and weather.

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